Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel) or porous rock. Production of natural gas from these types of formations typically involves drilling a well a desired depth into the formation, installing a casing in the wellbore (to keep the well bore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow into the casing, and installing a string of tubing inside the casing down to the production zone. Gas can then be made to flow up to the surface through a production chamber, which may be either the tubing or the annulus between the tubing and the casing.
Formation liquids, including water, oil, and/or hydrocarbon condensates, are generally present with natural gas in a subsurface reservoir. For reasons explained in greater detail hereinafter, these liquids must be lifted along with the gas. In order for this to happen, one of the following flow regimes must be present in the well:
Pressure-induced Flow
In a pressure-induced flow regime, the formation pressure (i.e., the pressure of the fluids flowing into the well) is greater than the hydrostatic pressure from the column of fluids (gas and liquids) in the production chamber. In other words, the formation pressure is sufficient to lift the liquids along with the gas. Pressure-induced flow occurs in wells producing from reservoirs having a non-depleting pressure; i.e., where the reservoir pressure is high enough that production from the reservoir results in no significant drop in formation pressure. This type of flow regime is common in reservoirs under water flood or having an active water drive providing pressure support. Conventional gas lift technology may be used to enhance flow in a pressure-induced flow regime by lightening the hydrostatic weight of total fluids in the production chamber.
Pressure-induced flow is most commonly associated with wells that are primarily oil-producing wells, and is rarely associated with primarily gas-producing wells.
Velocity-induced Flow
This type of flow occurs with gas reservoirs having a depleting pressure, and it is common in most gas reservoirs and all solution gas drive oil reservoirs. The present invention is concerned with velocity-induced flow, a general explanation of which follows.
In order to optimize total volumes and rates of gas recovery from a gas reservoir, the bottomhole flowing pressure should be kept as low as possible. The theoretically ideal case would be to have a negative bottomhole flowing pressure so as to facilitate 100% gas recovery from the reservoir, resulting in a final reservoir pressure of zero.
When natural gas is flowing up a well, formation liquids will tend to be entrained in the gas stream, in the form of small droplets. As long as the gas is flowing upward at or above a critical velocity (or “Vcr”—the value of which depends on various well-specific factors), the droplets will be lifted along with the gas to the wellhead, where the gas-liquid mixture may be separated using well-known equipment and methods. In this situation, the gas velocity provides the means for lifting the liquids; i.e., the well is producing gas by velocity-induced flow.
Formation pressures in virgin reservoirs of natural gas tend to be relatively high. Therefore, upon initial completion of a well, the gas will commonly rise naturally to the surface by velocity-induced flow provided that the characteristics of the reservoir and the wellbore are suitable to produce stable flow (meaning that the gas velocity at all locations in the production chamber remains equal to or greater than the critical velocity, Vcr—in other words, velocity-induced flow).
However, as wells penetrate the reservoir and gas reserves are removed, the formation pressure drops continuously, inevitably to a level too low to induce gas velocities high enough to sustain stable flow. Therefore, all flowing gas wells producing from reservoirs with depleting formation pressure eventually become unstable. Once the gas velocity has become too low to lift liquids, the liquids accumulate in the wellbore, and the well is said to be “liquid loaded”. This accumulation of liquids results in increased bottomhole flowing pressures and reduced gas recoveries. In this situation, continued gas production from the well requires the use of mechanical methods and apparatus in order to remove liquids from the wellbore and to restore stable flow.
The prior art discloses numerous examples of methods and equipment directed to extending the productive life of gas wells in which gas velocities are insufficient to convey gas to the wellhead without artificial assistance, and which are therefore susceptible to liquid loading.
U.S. Pat. No. 3,887,008 (Canfield), issued Jun. 3, 1975, discloses a jet compressor which may be installed within the tubing inside a cased gas well, wherein the annulus is sealed with a packer near the bottom of the tubing. The jet compressor has a low-pressure inlet exposed to the bottom of the wellbore, such that it is in communication with the gas-bearing formation through which the well has been drilled. A pressurized gas (which may be natural gas) injected down the annulus enters an inlet port in the jet compressor, via appropriately positioned openings in the casing. The jet compressor has a throat section configured to induce supersonic flow of gas moving upwardly therethrough. The injected gas entering the jet compressor thus is accelerated upward within the tubing, thereby creating a venturi effect that induces a reduction in bottomhole pressure and a consequent drawdown on the gas-bearing formation.
U.S. Pat. No. 5,911,278 (Reitz), issued Jun. 15, 1999, discloses a technique wherein a production tubing string is installed inside a cased wellbore down to the production zone, with a string of flexible tubing (or “macaroni tubing”) running down through the production tubing and terminating just above the bottom thereof. The casing is perforated in the production zone. The bottom of the production tubing is sealed off and fitted with a one-way valve that allows fluids to flow into the production tubing. There is no packer sealing off the annulus between the production tubing and the casing, so the annulus is in direct communication with the production zone of the well. Liquids present in the bottom of the well can therefore accumulate to similar levels in the macaroni tubing, the annulus between the macaroni tubing and the production tubing, and the annulus between the production tubing and the casing. The casing, production tubing, and macaroni tubing have separate valved connections to the suction manifold of a gas compressor near the wellhead, and to a wellhead production pipeline for formation liquids. As well, the production tubing and the casing have separate valved connections to the discharge manifold of the compressor.
In a situation where the casing, production tubing, and macaroni tubing all contain accumulations of liquids, the Reitz apparatus may operate in the “compression” cycle. The various valves of the apparatus are adjusted so as to open the production tubing to the discharge manifold (and close it to the suction manifold), to open the casing to the suction manifold (and close it to the discharge manifold), to close off the macaroni tubing from the suction manifold, and to close off all three of these components from the wellhead production line. The reduced pressure in the annulus between the casing and the production tubing (due to the suction from the compressor) causes additional formation fluids to enter the casing through the perforations. Pressurized gas flows into the production tubing from the discharge manifold, which because of the presence of the one-way valve causes the liquids to be evacuated from the production tubing into the macaroni tubing. At the same time, natural gas flows up to the compressor suction manifold through the annulus between the casing and the production tubing.
The compression cycle of the Reitz system is followed by a production cycle and an evacuation cycle, which are serially initiated by selective adjustment of the various control valves of the apparatus using an automatic controller of some type. These additional cycles are described in more detail in U.S. Pat. No. 5,911,278.
Perhaps the most common method of maintaining or restoring gas production in wells susceptible to liquid loading involves the use of a pump to remove liquids from the well. The pump may be a reciprocating pump operated by a “pump jack”, but other well-known types of pump may also be used. In any event, the pump is used to remove accumulated liquids through the tubing string, thus relieving the hydrostatic pressure at the bottom of the wellbore. In accordance with principles discussed previously, this induces further gas flow from the formation into the well and up the annulus.
The prior art technologies described above have proven useful for extending the productive life of gas wells that might otherwise have been abandoned due to liquid loading, but they have a number of drawbacks and disadvantages. For example, the Canfield system uses a downhole jet compressor of complex construction. If this jet compressor malfunctions, it must be retrieved from the tubing and then repaired or replaced, in either case resulting in expense and lost production. The Canfield system also requires the use of packers at the bottom of the tubing string.
Although the Reitz system does not employ specialized downhole devices or packers as in the Canfield system, it requires an additional tubing string (i.e., the macaroni tubing) running inside the production tubing, plus a one-way valve at the bottom of the production tubing. Malfunction of the one-way valve will require removal and replacement, resulting in expense and lost production. Further drawbacks of the Reitz apparatus include the requirement for a complex array of valves connecting the various well chambers to the compressor's suction and discharge manifolds, plus the need for a controller to manipulate the valves according to the system's various cycles. It is also noteworthy that gas production using the Reitz system is cyclical, not continuous.
The use of pumps to remove accumulated liquids from gas wells also has disadvantages, most particularly including the cost of providing, installing, and maintaining the pump equipment. A conventional reciprocating pump requires a string of “sucker rods” virtually the full length of the well, and if a rod breakage occurs, the entire string may need to be removed for repair, with consequent expense and loss of gas production.
An alternative approach to removing accumulated liquids from a gas well could involve injection of a pressurized gas into the well. Gas could be injected into the annulus (or the tubing) under sufficiently high pressure to blow the liquids up the tubing (or the annulus) and out of the well, thereby reducing or eliminating the hydrostatic pressure at the bottom of the wellbore. It might be intuitively thought that the effectiveness of such gas injection would increase with higher injection rates and pressures, but this is not necessarily true. The flow of a gas inside a conduit, such as the tubing or annulus in a well, causes “friction loading” due to friction between the flowing gas and the inner surfaces of the conduit.
Friction loading inside a well casing or tubing string has essentially the same effect as hydrostatic pressure caused by liquid loading; i.e., it effectively increases the bottomhole pressure, thus inhibiting gas flow into the well. Flow-induced friction forces increase with the square of the gas velocity, so efforts to increase gas production from marginal wells by increasing gas injection pressures and velocities may actually be counterproductive and futile. It is apparent that any prior attempts to enhance or restore gas production using only gas injection have not met with practical success, possibly because the disadvantageous effects of increased injection rates were not fully appreciated.
For the foregoing reasons, there is a need for improved methods and apparatus for extending the production life of gas wells subject or susceptible to liquid loading, by reducing bottomhole pressures so as to induce increased gas flows into the well, and by providing means for maintaining gas velocities in the well at or above the critical velocity in order to prevent accumulation of liquids in the wellbore. There is also a need for such improved methods and apparatus which involve the injection of a pressurized gas into the well, but without inducing excessive friction loading in the well. In addition, there is a need for methods and apparatus capable of carrying out these functions on a continuous rather than cyclic or intermittent basis. There is a further need for such methods and apparatus which do not entail the installation of valves, packers, compressors, or other appurtenances down the well, and without requiring more than one string of tubing inside the well casing. There is an even further need for such methods and apparatus which do not require a complex array of valves and associated piping at the wellhead. The present invention is directed to these needs.